The present invention relates to a method for continuously detecting and monitoring the presence of volatile gases in oils and other fluids used to insulate electrical equipment. In particular, the invention relates to a method for quantitatively determining the specific concentration of certain gases, particularly hydrocarbons, dissolved in insulating fluids on a continuous, real time basis in order to evaluate the operation of the electrical devices while the equipment is still in operation. The invention also relates to an apparatus for simultaneously measuring the concentrations of several different gas components dissolved in an insulating fluid and/or the vapor phase constituents on a continuous, real time basis.
Oil-filled equipment, such as transformers, shunt reactors, current transformers and bushings, are considered to be among the most critical elements of almost any electrical power system. As a result, the continued, reliable performance of such equipment is essential to the efficient generation and transmission of electrical power. In addition, the catastrophic failure and resulting unavailability of oil-filled equipment can have serious, even life-threatening, consequences for end users and can result in a substantial loss of revenue to consumers and utilities. An unexpected power failure can also cause significant damage to peripheral operating equipment, such as electrical manufacturing devices, or result in collateral environmental damage, or require the use of emergency alternative power sources during and after the failure.
Thus, the early detection of incipient faults in oil-filled equipment used in the transmission or control of electrical power, such as transformers and shunt reactors, can have a significant, measurable impact on end users and effect the overall reliability and profitability of electric utilities. The effective monitoring of electrical equipment performance levels to detect faults also provides end users with the opportunity to strategically plan and schedule power outages or routine maintenance, and thereby better manage power equipment utilization and its availability in specific geographic markets. The total operating costs for electrical grids can also be significantly reduced if the utility uses equipment that can be repaired within a scheduled repair plan or can be taken out of service at the first sign of trouble before a catastrophic failure occurs.
For many years, electric utilities have recognized the need to monitor the performance level over extended periods of time of critical pieces of power equipment in order to extend the useful life of the equipment and prevent catastrophic failures. Various insulating dielectric fluids (typically consisting of one or more chemically stable hydrocarbon fluids) have been used in the past with transformers and other like equipment to electrically isolate the transmission subsystems. Dielectric oil and solid cellulose dielectric materials are perhaps the best known insulating materials used for such purposes. Even during normal operating conditions, these insulating materials tend to degrade and break down under the inherent thermal and electrical stresses in the system. The degradation process creates by-product gases (generally low molecular weight hydrocarbons) of varying composition and different concentrations, depending on the severity and duration of the electrical stresses placed on such materials. Even under normal operating conditions, a small, but stable amount of gas and water vapor are produced during degradation.
That is, it is known that a measurable portion of the by-product gases dissolve in the dielectric oil at a given operating temperature and pressure and that data reflecting the nature and amount of individual gases sampled during operation can be used to identify the type and severity of the corresponding electrical fault in the equipment (such as a transformer malfunction). Even minute detected changes in the chemical composition of the gas produced and the rate of gas production over time can be important factors in determining the type of fault(s) involved, the evolution of the fault(s) and the potential consequences to related pieces of equipment. Thus, the detection of certain types of gas compounds can be correlated with known electrical faults. If rapid overheating or arcing occurs in the system, a substantial amount of gases and water vapor will be produced in a short period of time. Typically, the hydrocarbon-based dielectric oil produces free hydrogen, hydrocarbons, carbon dioxide and/or carbon monoxide gases as it thermally degrades (xe2x80x9cbreaks downxe2x80x9d), while most dielectric paper substrates produce only carbon monoxide, carbon dioxide and water.
Because different dissolved gases and vapor (which typically includes water) indicate developing faults in the equipment, the dissolved gas data can be used to predict future faults and changing operating conditions. Thus, as noted above, accurate measurements of the levels of dissolved gases and/or vapor on a real time basis can be critical to understanding and predicting the health of an entire, integrated electrical network and can help identify electrical problems that arise before a catastrophic failure ensues.
The degradation of conventional dielectric oils normally produces hydrogen, methane, ethane, ethylene and acetylene in gas form. Any overheating of oil due to partial electrical discharges or partial arcing will produce one or more of those gases in varying amounts under different operating conditions. xe2x80x9cHot spotsxe2x80x9d in the equipment can often cause portions of the dielectric oil to overheat, producing primarily ethylene and measurable concentrations of hydrogen. Partial electrical discharges typically produce only hydrogen and methane. More severe arcing, on the other hand, can result in higher concentrations of hydrogen and acetylene which increase in amount as the oil fault temperature increases. Certain gases are known to be associated with each type of fault. Thus, the detection of individual gases and the rate of degradation depend on the type of dielectric, the nominal temperature of the oil at the point of degradation and the amount of heat energy being released into the oil at the fault location (the xe2x80x9chot spotxe2x80x9d).
In like manner, the thermal degradation of oil-impregnated cellulose materials produces different amounts of carbon monoxide, carbon dioxide and water, depending on the dielectric involved, the amount of heat generated and nominal operating conditions. Similar xe2x80x9chot spotsxe2x80x9d in windings, insulated leads and areas where pressboard and cellulose components and spacers are used also produce gases during degradation. Again, these hot spots tend to be localized and decompose the solid insulation in the specific areas of electrical stress.
In the past, users of electrical equipment, particularly transformers, have attempted to monitor and predict failures by manually taking samples from the insulating fluids at prescribed time intervals and then analyzing the samples at a location remote from the equipment itself. Free gases were also extracted from the xe2x80x9chead spacexe2x80x9d of the transformer or other equipment using known sampling techniques and then injected into a gas chromatograph in order to determine the concentration and identity of the components in the extracted material. This procedure might be repeated several times a day to determine trends in the concentration of gases dissolved in the fluid. If the equipment owner failed to periodically test for rising levels of dissolved gases and water vapor in the head space, or misread or overlooked the data, the associated electrical equipment could fail, resulting in costly replacement and general power deterioration and/or outages. The degradation caused by electrical faults can occur very quickly. Thus, even sporadic sampling at prescribed time intervals is not effective in preventing significant damage to a transformer or downstream equipment.
Thus, for many years a significant need has existed for a reliable and cost-effective method and an apparatus capable of continuously and quantitatively detecting and measuring the concentration of selective dissolved gas and/or vapor components in fluids used to insulate electrical equipment.
Most electric utilities in the United States still use some form of periodic dissolved gas analysis (like DGA), with scheduled sampling, chromatographic analysis in the laboratory and fault diagnosis in order to identify and predict failure conditions of transformers. A clear need exists therefore for a method to detect and monitor a change in fault gases on a continuous basis, for example in a manner capable of linking individual DGA events. There are many well-documented cases of a critical power transformer failing catastrophically within days or even hours after being energized and/or after the onset of an increasing change in gas production due to oil degradation. With short fault development periods it is impractical, if not impossible, to identify serious faults with an annual or semi-annual monitoring event.
The present invention offers a significant improvement over prior art detection and monitoring equipment by providing a method and apparatus for the continuous detection and analysis of incipient electrical faults in transformers and like equipment. The disclosed method and apparatus will also substantially reduce, if not eliminate, unplanned power outages of transformers and other equipment, thereby improving the overall reliability of power grids and power transmission to end users.
The present invention also represents a cost-effective and more reliable apparatus and method for quantitatively determining the concentrations of certain dissolved and vapor phase constituents resulting from the expected degradation of dielectric fluids, and for making such quantitative determinations on a substantially real time, i.e., continuous basis. Because even minor electrical fault conditions can lead to catastrophic failures of downstream equipment, the method and apparatus according to the invention allow for early fault detections while providing continuous information regarding detected faults, including alarms, to end users such as substation personnel, thereby enhancing the overall safety of the personnel and protecting the operating integrity of downstream equipment. Also disclosed is the preferred means for detecting rapidly developing electrical faults on a real time basis and providing emergency information to end users who can then marshal the resources necessary to reduce or prevent potential damage to other power equipment.
The present invention satisfies a significant need in the electrical field by providing a novel means for detecting, analyzing and monitoring the levels of certain dissolved gases and/or vapor components (including water vapor) of an insulating fluid. The present invention also provides means for measuring the concentration of the by-products of degradation on a continuous, substantially real-time basis and then evaluating the measured data in order to determine current equipment performance and prevent future equipment failures.
The present invention utilizes a continuous flow design capable of providing constant, updated information regarding the specific concentration of selected dissolved gases and/or vapor. The apparatus according to the invention is capable of detecting and analyzing up to three different components simultaneously and supplying accurate numeric concentration levels for each component. If the concentration of gases and/or vapor rises quickly or approaches a hazardous level, an alarm can also be triggered based on the detected data.
The concentrations of gases and water vapor in the dielectric fluid are calculated by the concentrations of the gases and water vapor in the extracted gas phase using known solubility coefficients. The gas membrane extraction process itself is dynamic in nature. That is, gases can permeate in either direction across the barrier, thereby allowing for measurements of decreasing concentrations as well as increasing concentrations.
The preferred method for analyzing and measuring the gas and/or vapor components in an insulating fluid according to the present invention includes the following basic steps:
passing a fluid by one side of a membrane to extract the dissolved gas and/or vapor components from the fluid;
analyzing the gas and/or vapor in an infrared gas cell detection system to determine the identity and concentration of the components; and
recirculating the gases and/or vapor back to the extraction unit to maintain equilibrium across the membrane.
The preferred embodiment of the invention includes an apparatus for implementing the above described method, that includes:
a gas extractor unit for separating the gases and/or vapor (including water) from the fluid, comprising a gas-permeable membrane and a small gas chamber with one gas stream inlet and one gas stream outlet;
an infrared gas analyzer for determining the component concentration, comprising a collimated infrared source, a gas cell with gas inlet and outlet at both ends, a quad detector with integral optical infrared filters, an infrared source controller, and a detector signal processor; and
a gas pump for circulating the extracted gases and/or vapor from the gas chamber to the gas analyzer in a closed loop.
In the preferred embodiment, the system analyzes two gases, ethylene and carbon monoxide, and one vapor, water. The detection limits are 6 parts per million (v/v) for ethylene; 5 parts per million (v/v) for carbon monoxide; and 5% Relative Humidity for water. The nominal insulating oil is conventional transformer oil and the membrane preferably consists of fluorosilicone or perfluoro polymer. The system can be expanded to monitor additional gases and/or vapor components.